Hydraulic fracturing in highly heterogeneous formations by fluid selection based on fracture surface roughness

ABSTRACT

Well completion technology is disclosed for accounting for fracture surface roughness. A frack fluid is pumped into the wellbore to form a fracture in a formation surrounding a wellbore. In one example, a method for completing a wellbore comprises determining a fracture surface roughness for a given formation rock, and for a give fracture fluid or pumping schedule or both, prior to hydraulic fracturing. A fracture fluid and/or a pumping schedule is selected based on the determined fracture surface roughness and formation characteristics. The selected fracture fluid is pumped into the wellbore, with the selected pumping schedule, to create a desired fracture network in the formation.

PRIORITY CLAIM

Priority is claimed to copending U.S. Provisional Patent ApplicationSer. Nos. 62/345,494; 62/345,553; 62/345,590; 62/345,627; and 62/345,654filed Jun. 3, 2016, which are hereby incorporated herein by reference intheir entirety.

TECHNICAL FIELD

Embodiments described herein relate generally to hydraulic fracturingand completing a wellbore.

BACKGROUND

Hydraulic fracturing (or “fracking”) for oil and gas well productionstimulation is very important and is a very large business. But frackingcontinues in many cases with a “brute force” approach that is extremelylarge scale, leading to poor economic returns and adverse environmentalimpacts. Additionally, the recovery factor for the unconventional tightshale formations rapidly being exploited in the US is low, and in manycases maybe only 10% of oil and 20% of natural gas is recovered.

BRIEF DESCRIPTION OF THE DRAWINGS

Invention features and advantages will be apparent from the detaileddescription which follows, taken in conjunction with the accompanyingdrawings, which together illustrate, by way of example, variousinvention embodiments; and, wherein:

FIG. 1 is a cross-sectional perspective schematic view of a well with avertical section that is turned to create a horizontal lateral portionof the well.

FIG. 2 is a cross-sectional side schematic view of a horizontal well anda hydraulic fracture with its “parts.”

FIG. 3 is a schematic perspective view of a showing a crack tipdemonstrating a micro process.

FIG. 4 is a schematic view of a very blunted crack tip creating a largerfracture width towards the crack tip.

FIG. 5 is a schematic view of a very pointed crack tip creating a narrowfracture width toward the crack tip.

FIG. 6 is a schematic view of a process zone stress intensity profilewith a fracture growing vertically across the laminations.

FIG. 7 is a schematic view of a process zone stress intensity profilewith a fracture growing horizontally parallel to the laminations.

FIG. 8 is graph showing fluid velocities in feet per second versusdistance from the wellbore for different leak-off conditions for a shalewith intermediate stiffness and estimated in situ stresses.

FIG. 9 is a graph showing the pressure drop versus the fluid velocitybased on a calculation for water flowing in a 1 mm height channel withwall roughness estimated as sinusoidal irregularities with height of tenpercent of the channel thickness.

Reference will now be made to the exemplary embodiments illustrated, andspecific language will be used herein to describe the same. It willnevertheless be understood that no limitation of the scope or tospecific invention embodiments is thereby intended.

DESCRIPTION OF EMBODIMENTS

Before invention embodiments are disclosed and described, it is to beunderstood that no limitation to the particular structures, processsteps, or materials disclosed herein is intended, but also includesequivalents thereof as would be recognized by those ordinarily skilledin the relevant arts. It should also be understood that terminologyemployed herein is used for the purpose of describing particularexamples only and is not intended to be limiting. The same referencenumerals in different drawings represent the same element. Numbersprovided in flow charts and processes are provided for clarity inillustrating steps and operations and do not necessarily indicate aparticular order or sequence. Unless defined otherwise, all technicaland scientific terms used herein have the same meaning as commonlyunderstood by one of ordinary skill in the art to which this disclosurebelongs.

As used in this specification and the appended claims, the singularforms “a,” “an” and “the” include plural referents unless the contextclearly dictates otherwise. Thus, for example, reference to “a layer”includes a plurality of such layers.

In this disclosure, “comprises,” “comprising,” “containing” and “having”and the like can have the meaning ascribed to them in U.S. Patent lawand can mean “includes,” “including,” and the like, and are generallyinterpreted to be open ended terms. The terms “consisting of” or“consists of” are closed terms, and include only the components,structures, steps, or the like specifically listed in conjunction withsuch terms, as well as that which is in accordance with U.S. Patent law.“Consisting essentially of” or “consists essentially of” have themeaning generally ascribed to them by U.S. Patent law. In particular,such terms are generally closed terms, with the exception of allowinginclusion of additional items, materials, components, steps, orelements, that do not materially affect the basic and novelcharacteristics or function of the item(s) used in connection therewith.For example, trace elements present in a composition, but not affectingthe composition's nature or characteristics would be permissible ifpresent under the “consisting essentially of” language, even though notexpressly recited in a list of items following such terminology. Whenusing an open ended term in the specification, like “comprising” or“including,” it is understood that direct support should be affordedalso to “consisting essentially of” language as well as “consisting of”language as if stated explicitly and vice versa.

The terms “first,” “second,” “third,” “fourth,” and the like in thedescription and in the claims, if any, are used for distinguishingbetween similar elements and not necessarily for describing a particularsequential or chronological order. It is to be understood that the termsso used are interchangeable under appropriate circumstances such thatthe embodiments described herein are, for example, capable of operationin sequences other than those illustrated or otherwise described herein.Similarly, if a method is described herein as comprising a series ofsteps, the order of such steps as presented herein is not necessarilythe only order in which such steps may be performed, and certain of thestated steps may possible be omitted and/or certain other steps notdescribed herein may possible be added to the method.

The terms “left,” “right,” “front,” “back,” “top,” “bottom,” “over,”“under,” and the like in the description and in the claims, if any, areused for descriptive purposes and not necessarily for describingpermanent relative positions. It is to be understood that the terms soused are interchangeable under appropriate circumstances such that theembodiments described herein are, for example, capable of operation inother orientations than those illustrated or otherwise described herein.The term “coupled,” as used herein, is defined as directly or indirectlyconnected in an electrical or nonelectrical manner. Objects describedherein as being “adjacent to” each other may be in physical contact witheach other, in close proximity to each other, or in the same generalregion or area as each other, as appropriate for the context in whichthe phrase is used. Occurrences of the phrase “in one embodiment,” or“in one aspect,” herein do not necessarily all refer to the sameembodiment or aspect.

As used herein, the term “substantially” refers to the complete ornearly complete extent or degree of an action, characteristic, property,state, structure, item, or result. For example, an object that is“substantially” enclosed would mean that the object is either completelyenclosed or nearly completely enclosed. The exact allowable degree ofdeviation from absolute completeness may in some cases depend on thespecific context. However, generally speaking the nearness of completionwill be so as to have the same overall result as if absolute and totalcompletion were obtained. The use of “substantially” is equallyapplicable when used in a negative connotation to refer to the completeor near complete lack of an action, characteristic, property, state,structure, item, or result. For example, a composition that is“substantially free of” particles would either completely lackparticles, or so nearly completely lack particles that the effect wouldbe the same as if it completely lacked particles. In other words, acomposition that is “substantially free of” an ingredient or element maystill actually contain such item as long as there is no measurableeffect thereof.

As used herein, the term “about” is used to provide flexibility to anumerical range endpoint by providing that a given value may be “alittle above” or “a little below” the endpoint. It is understood thatexpress support is intended for exact numerical values in thisspecification, even when the term “about” is used in connectiontherewith.

As used herein, a plurality of items, structural elements, compositionalelements, and/or materials may be presented in a common list forconvenience. However, these lists should be construed as though eachmember of the list is individually identified as a separate and uniquemember. Thus, no individual member of such list should be construed as ade facto equivalent of any other member of the same list solely based ontheir presentation in a common group without indications to thecontrary.

Concentration, amounts, sizes, and other numerical data may be expressedor presented herein in a range format. It is to be understood that sucha range format is used merely for convenience and brevity and thusshould be interpreted flexibly to include not only the numerical valuesexplicitly recited as the limits of the range, but also to include allthe individual numerical values or sub-ranges encompassed within thatrange as if each numerical value and sub-range is explicitly recited. Asan illustration, a numerical range of “about 1 to about 5” should beinterpreted to include not only the explicitly recited values of about 1to about 5, but also include individual values and sub-ranges within theindicated range. Thus, included in this numerical range are individualvalues such as 2, 3, and 4 and sub-ranges such as from 1-3, from 2-4,and from 3-5, etc., as well as 1, 2, 3, 4, and 5, individually.

This same principle applies to ranges reciting only one numerical valueas a minimum or a maximum. Furthermore, such interpretation should applyregardless of the breadth of the range or the characteristics beingdescribed.

Reference throughout this specification to “an example” means that aparticular feature, structure, or characteristic described in connectionwith the example is included in at least one embodiment. Thus,appearances of the phrases “in an example” in various places throughoutthis specification are not necessarily all referring to the sameembodiment.

Furthermore, the describe features, structures, or characteristics maybe combined in any suitable manner in one or more embodiments. In thisdescription, numerous specific details are provided, such as example oflayouts, distances, network examples, etc. One skilled in the relevantart will recognize, however, that many variations are possible withoutone or more of the specific details, or with other methods, components,layouts, measurements, etc. In other instances, well-known structures,materials, or operations are not shown or described in detail but areconsidered well within the scope of the disclosure.

The terms smooth and rough are used herein to refer to the surfaceroughness or anticipated surface roughness of the fracture. The termsmooth can be defined as the fracture surface local variation of theorder of less than 100 times the largest average particle size; whilerough can be defined as greater than 100 times the largest averageparticle size. Particle size refers to the size of the makeup of thecomponents of the rock or formation in which the fracture is formed,including mineral particles and organic particles. Fracture smoothnessor roughness does not refer to fracture surface waviness on the scale ofinches to feet, fracture step-overs of less than an inch to feet,fracture interception and propagation along planes of weakness, or thelike. Smoothness or roughness refers to the small-scale rock fracturesurface.

The terms frack fluid and fracture fluid are used interchangeably hereinto refer to the fluid used for creating a fracture and/or the fluid inaddition to a proppant added to the fluid. The frack fluid can have aviscosity, or the frack fluid with proppant or other additives can havean effective viscosity. Selecting a frack fluid based on the surfaceroughness or desired surface roughness of the fracture can compriseselecting the frack fluid itself based on the characteristics of thefracture fluid alone, or selecting the frack fluid based on theeffective characteristics of the fracture fluid in combination with theproppant or other additives.

The terms micro-fracture and transverse micro-fracture are usedinterchangeably herein to refer to undesirable secondary micro-fracturesor cracks in the inner surface of the fracture, and through which frackfluid can undesirably seep, leak, imbibe, etc. Such micro-fractures canbe formed by the fracking process, i.e. the pumping of frack fluid intothe fracture at high pressure. In addition, the transversemicro-fractures can be natural flaws or defects in the formation thatare weak in shear and which enhance fracture breakdown in initiation.The pumping of the frack fluid into the fracture can exasperate thenatural flaws or defects. The transverse micro-fractures can becharacterized by a size less than a size of the fracture. Thus, themicro-fractures can have a size or aperture of less than 0.1 mm. Theterm “transverse” is used herein to refer to a direction of themicro-fracture across the fracture or inner face of the fracture. Thetransverse direction can be perpendicular to the fracture or inner faceof the fracture, but can also be oriented at an oblique angle to thefracture or inner face of the fracture.

Example Embodiments

An initial overview of technology embodiments is provided below andspecific technology embodiments are then described in further detail.This initial summary is intended to aid readers in understanding thetechnology more quickly but is not intended to identify key or essentialfeatures of the technology nor is it intended to limit the scope of theclaimed subject matter.

It has been recognized by the inventor that the fracking process isdynamic, with the fracture progressing with time, and the process isfluid flow and fracture coupled including rock-fluid interactions.Furthermore, the process is truly three-dimensional, which is difficultto project visually; and as for many three-dimensional processes, atwo-dimensional representation may not at all visually depict theprocess. That is the case for hydraulic fracturing.

In addition, it has been recognized by the inventor that it would beadvantageous to develop a method to account for fracture surfaceroughness in the fracture propagation process. In addition, it has beenrecognized by the inventor that the fracture surface roughnesscontributes to the development of the fracture, and that determining oreven tailoring the surface fracture roughness can help develop a desiredfracture network, such a complex fracture network, a fracture networkthat cuts across formation interfaces, or that is contained within theformation interfaces. In addition, it has been recognized by theinventor that it would be advantageous to develop a method to accountfor fluid-rock interaction, such as wetting or non-wetting between afracture surface and the fracture fluid. Furthermore, it has beenrecognized by the inventor that it would be advantageous to develop amethod to create a desired facture network and a desired fracturesurface roughness.

A method for completing a wellbore and/or for propagating a hydraulicfracture comprises determining a fracture surface roughness for a givenformation rock, and for a give fracture fluid or pumping schedule orboth, prior to hydraulic fracturing. In one aspect, the give formationcan comprise heterogeneous shale. A fracture fluid and/or a pumpingschedule is selected based on the determined fracture surface roughnessand formation characteristics. The selected fracture fluid is pumpedinto the wellbore, with the selected pumping schedule, to create adesired fracture network in the formation.

In one aspect, the fracture surface roughness can be determined byobtaining a core sample with formation characteristics of the giveformation rock. A fluid fracturing test and/or a mechanical wedgingfracture test can be conducted on the core sample. Thus, the surfaceroughness of the core sample can be observed and measured to determine aprobable fracture surface roughness of the hydraulic fracture. Inaddition, the fracture fluid and/or pumping schedule can be taken intoconsideration with respect to the observed and/or measured surfaceroughness of the core sample to determine the probable fracture surfaceroughness of the hydraulic fracture.

The Process of Hydraulic Fracturing in Tight Shales

Fluid driven fractures in non-homogeneous non-continuum complicated rockformations such as the “tight shales”, under high compressive stressesas exists deep in the earth, is a complex process. It is a process thathas attracted many researchers to make calculations of ideal materialsin an attempt to simulate the process. And it is a process that hascaused practitioners to proceed in a trial-and-error manner to drill andcomplete and produce oil and gas without truly understanding theprocess. Organic-rich mudstones (the so called “tight shales” or “blackshales”) are heterogeneous at all scales. These tight shales arecomposed of hard strong sub-micron size mineral particles, clayplatelets, organic matter, and micro to nano meter scale pores filledwith different fluids including water, methane, and hydrocarbon liquids.

Furthermore, the tight shales also contain discontinuities—often called“planes of weakness”—consisting of layer or bedding interfaces, naturaland usually tightly filled fractures, thin interfaces or zones ofdifferent materials, and high-strength inclusions. Interface makeup andmechanical properties variations between the shale units can result inthese interfaces being weak in shear strength. Such interfaces candrastically affect hydraulic fracture formation.

Based on the known tight shale make-up, it is not reasonable to believethat hydraulic fracture occurs as for a homogeneous continuumelastic-brittle material. In practice the hydraulic fracture is morecomplicated. How the fracture emanates from the wellbore is not clear,but generally it is assumed that a single fracture propagates from eachperforation cluster, notched interval, or sliding sleeve opening, andgrowth tends to be at least somewhat centered around the wellbore. Thefracture can be complicated and may be somewhat elliptical in shape notnecessarily symmetrical about the well bore. For the tight shales therewill be branching and step-over's leading to a complex fracture network.Furthermore, it is not uncommon for the fracture to reach an interfaceand turn and propagate within the interface for some short distance, oreven for long distances.

At some time proppant (most often sand but sometimes ceramics or othermaterials) is added to be carried with the fracture fluid and ultimatelyleft in the fracture to prop open the fracture after pumping stops. Indetail, the process is complicated and involves practice that has beendeveloped over time by industry drilling tens of thousands of tightshale wells.

Fluid Driven Fractures

The process of a fluid driven fracture in tight shales deep in the earthmay be visualized as the following. For homogeneous continuous rock(considering an ideal situation), as more fracture fluid is injectedinto an already existing fracture, the fracture fluid “pries” thefracture further open by the fracture fluid pressure increase. Stresseschange in the rock all around the fracture and particularly in theregion of the fracture tip. These stress adjustments travel with thespeed of sound in the rock, several thousand feet per second—exceedinglyfast, almost instantaneously for the process here. For anelastic-brittle substance (which may be more like granite rock, but notthe shales) shear and tensile stresses would build in the region verynear the crack tip. When a certain stress intensity is reached in thisvery small region near the crack tip, fracturepropagation—extension—occurs.

The crack propagation speed is not well known; some estimate about halfthe speed of sound in geo materials. The Rayleigh wave speed would be anupper bound, about two-thirds the speed of sound for ideal rock. Thefracture fluid will start to move with the crack growth, but cannot keepup with such high crack growth speed. At best the fluid velocity couldbegin to move at the speed of sound in the fracture fluid, as the fluideffectively decompressed in the fracture. Without the fluid keeping upwith the crack growth, the crack eventually stops growing. The fluidcatches up, wedging opening the fracture; the crack eventually growsagain; and so forth. A step process would occur.

For the shales (which are not a homogeneous continuous material), theabove fracture propagation model is not completely the case. As fluid isinjected into an already existing fracture and fracture fluid pressureincreases, and stress adjustments do occur with the speed of sound inthe shale. And, stresses near the crack tip increase, leading to rockdamage in a region near the crack tip until failure occurs and the crackadvances. The region around the crack tip is complicated and will affectthe fracture growth speed.

Fracture Fluid Velocities During Fracture Propagation

Based on a conservation of mass, the fracture fluid velocity in thenarrow fracture can be estimated as the fracture length grows away fromthe wellbore. The fracture width and the leak-off into the surroundingformation can be estimated. FIG. 8 shows fluid velocities in feet persecond for different leak-off conditions for a shale with intermediatestiffness and estimated in-situ stresses. The injection rate is 12barrels per minute continuous at the wellbore of slick water as thefracture fluid. The estimated fracture widths are taken from aquasi-three dimensional planar fracture calculation with no heightcontainment (approximately circular fracture). Three different leak-offsare shown, with the top line no leak-off, the bottom line leaking offabout 50 percent by time the fracture has grown 50 feet from thewellbore, and the middle line is an intermediate leak-off of about 25percent. The fracture is taken as symmetrical around the wellbore; the“half length” is the distance of the fracture tip from the wellbore.

Fracture fluid velocities beginning a few feet away from the wellbore(not right at the wellbore) range from about 10 feet per seconddeclining to about 1 foot per second at about 50 feet from the wellborefor a leak-off of nearly fifty percent by time the fracture has reached50 feet from the wellbore (the bottom line). If non-homogeneousfingering would occur (instead of homogeneous circular growth), it isestimated that the fluid velocity in the “finger” fracture extensionwould have to be upwards of one hundred times the fluid velocity for thehomogeneous expanding circular fracture. The primary slowing of thefracture fluid velocities for a given injection rate and a given fluidis due to dispersion (increasing diameter of the fracture), and secondlyto fluid leak-off. Fracture width variation is a small effect. Highfracture fluid velocities would lead to large pressure drops required tomove different fluids through the narrow fractures. These pressure dropsalong the fracture for the high fluid velocities contribute to thecomplex fracture formation.

Fracture Fluid Pressure Drop along the Fracture

Calculations show fracture fluid pressure drop as the fluid is flowingin a narrow channel at high velocities. FIG. 9 shows the pressure dropversus the fluid velocity. This calculation is for water flowing in a 1mm height channel with wall roughness estimated as sinusoidalirregularities with height of ten percent of the channel thickness. Forthis case, pressure drop at 1 foot per second fluid velocity is about 15psi per foot, while at 10 feet per second velocity pressure drop isabout 340 psi per foot. And, at 100 feet per second velocity thepressure drop is about 1300 psi per foot. These pressure drops per footwould lower the net pressure in the fracture (the difference between thefracture fluid pressure and the rock pore pressure) significantly alongthe fracture length, particularly near the fracture tip even for slickwater. Considering that a net pressures as low as 50 psi has beenclaimed to cause a fracture to extend in the shales, the pressure dropsper foot shown above are large.

The fracture surface roughness can be an important factor. Differentshales show different fracture surface roughness—some relatively smoothand some much rougher (as defined above). Also, the fluid properties ofviscosity and shale wetting or non-wetting can be key parameters, andhave yet to be considered in the calculations. The basis for thesecalculations notes that the flow resistance will increase as the cube ofthe channel height decreases. Thus, as the fracture width decreaseslarge pressure drops occur. The Reynolds number can be critical, and anincrease in the pressure gradient versus velocity tends to occur atabout 10 feet per second (for water) where the Reynolds number is a fewthousand. The pressure drop along the fracture should be considered.

Fracture Fluid Selection Based on Fracture Face Roughness

Fluid flow at high velocities in the narrow fracture is significantlyaffected by the fracture face surface roughness. The addition ofproppant materials in the fluid amplifies the surface roughness affects,as well as the fluid-rock interaction; i.e. for example wetting ornon-wetting fluids. Selecting the fracture fluid, or pumping schedule,or both, based on the fracture surface roughness and formationcharacteristics, and/or the fluid-rock interaction, can: result in alower or a higher pressure drop along the fracture, as desired, tocreate a more productive fracture network within a petrophysical sweetspot of the given formation rock; favorably alter interaction of thefracture propagation with a discontinuity; change the complicity orsimplicity of the fracture network; change proppant transport throughthe fracture; cause or minimize proppant screen-out; and/or increasefracture length.

A method for completing a wellbore and/or for propagating a hydraulicfracture comprises determining a fracture surface roughness for a givenformation rock, and for a given fracture fluid or pumping schedule orboth, prior to hydraulic fracturing. In one aspect, the give formationcan comprise heterogeneous shale. In another aspect, a desired fracturesurface roughness can be obtained to create the desired facture network.

As described above, the terms smooth and rough are used herein to referto the surface roughness or anticipated surface roughness of thefracture or face or surface of the fracture. The term smooth can bedefined as the fracture surface local variation of the order of lessthan 100 times the largest average particle size; while rough can bedefined as greater than 100 times the largest average particle size.Particle size refers to the size of the makeup of the components of therock or formation in which the fracture is formed, including mineralparticles and organic particles. Fracture smoothness or roughness doesnot refer to fracture surface waviness on the scale of inches to feet,fracture step-overs of less than an inch to feet, fracture interceptionand propagation along planes of weakness, or the like. Smoothness orroughness refers to the small-scale rock fracture surface.

In one aspect, the fracture surface roughness can be determined byobtaining a core sample with formation characteristics of the givenformation rock. A fluid fracturing test and/or a mechanical wedgingfracture test can be conducted on the core sample. Thus, the surfaceroughness of the core sample can be observed and measured to determine aprobable fracture surface roughness of the hydraulic fracture. Inanother aspect, the fracture surface roughness can be determined byobtaining an analog rock or that has already been measured as to itsfracture surface roughness. In addition, the fracture fluid and/orpumping schedule can be taken into consideration with respect to theobserved and/or measured surface roughness of the core sample todetermine the probable fracture surface roughness of the hydraulicfracture.

The method also comprises selecting a fracture fluid and/or a pumpingschedule based on the determined and/or desired fracture surfaceroughness and formation characteristics. The selected fracture fluid ispumped into the wellbore, with the selected pumping schedule, to createa desired fracture network in the formation. In one aspect, the fracturefluid selected can also comprise selecting additives, such as proppants.In another aspect, selecting the fracture fluid can comprise selecting aviscosity of the fracture fluid, or an effective viscosity of thefracture fluid and additives, based on the fracture surface roughness.In one aspect, it is believed that a lower viscosity or effectiveviscosity fracture fluid may result in a smoother fracture surfaceroughness. In another aspect, the pumping schedule can comprise thepumping rate.

In some situations is can be desirable to have a smooth fracture surfaceroughness; such as to propagate a fracture network that cuts acrossformation interfaces to achieve a greater fracture height in theformation. In one aspect, the fracture fluid and/or the pumping schedulecan be selected to obtain a smooth fracture surface roughness at acloser distance from the wellbore less than 20 feet. In another aspect,the fracture fluid and/or the pumping schedule can be selected to obtaina smooth fracture surface roughness at a further distance from thewellbore greater than 20 feet in order to obtain a fracture network thatcuts across formation interfaces to achieve a greater fracture height.In some situations it can be desirable to have a rough fracture surfaceroughness; such as to propagate a fracture network that is contained inthe formation, and that does not cut across formation interfaces. Inanother aspect, the fracture fluid and/or the pumping schedule can beselected to obtain a rough fracture surface roughness at a furtherdistance from the wellbore greater than 20 feet to obtain a fracturenetwork that is contained and does not cut across formation interfacesto achieve a greater fracture height containment.

As described above, in one aspect, the fracture fluid and/or the pumpingschedule can be selected based on the given formation rock, and givenin-situ stresses in the formation, to obtain a desired fracture surfaceroughness to create the desired facture network. In one aspect, it isbelieved that the fracture fluid and/or the pumping schedule can beselected to make the formation fail in extension, rather than tension,to obtain a smoother fracture surface roughness.

Also as described above, the selected fracture fluid and/or the selectedpumping schedule based on the fracture surface roughness can: result ina lower or a higher pressure drop along the fracture, as desired, tocreate a more productive fracture network within a petrophysical sweetspot of the given formation rock; favorably alter interaction of thefracture propagation with a discontinuity; change the complexity orsimplicity of the fracture network; change proppant transport throughthe fracture; cause or minimize proppant screen-out; and/or increasefracture length.

In addition, the method can further comprise determining a fluid-rockinteraction. In one aspect, the fluid-rock interaction can comprisewetting or non-wetting between a fracture surface and the fracturefluid. Determining the fluid-rock interaction can comprises obtaining acore sample with formation characteristics of the given formation rock,and conducting a fluid wettability test on the core sample. The fracturefluid can be selected based on the fluid-rock interaction.

As described above, the selected fracture fluid based on the fluid-rockinteraction can result in a lower or a higher pressure drop along thefracture, as desired, to create a more productive fracture networkwithin a petrophysical sweet spot of the given formation rock; favorablyalter interaction of the fracture propagation with a discontinuity;change the complexity or simplicity of the fracture network; changeproppant transport through the fracture; cause or minimize proppantscreen-out; and/or increases fracture length.

Furthermore, the method can comprise determining a desired fracturesurface roughness for a given formation rock prior to hydraulicfracturing. A fracture fluid and/or a pumping schedule can be selectedbased on the desired fracture surface roughness for the given formationrock and anticipated stresses in the formation. The fracture fluid canbe pumped into the wellbore to create a desired fracture network withsubstantially the desired surface roughness.

Hydraulic Fracture “Parts”

The “Parts” of the hydraulic fracture are shown schematically in FIG. 2.The wellbore 1 can extend vertically only, or can also extendhorizontally. A “connector” 2 extends out a first few feet toapproximately ten feet from the wellbore 1. The connector 2 can beaffected by stress shadowing from other fractures. A propped fracture 3can extend approximately fifty feet to approximately one to two hundredfeet in distance from the connector 2. The propped fracture 3 canaccount for nearly all of the well production. The transversemicro-fractures 4 can extend transverse (perpendicular and/or obtuse) tothe fracture 3. The transverse micro-fractures 4 can extend a few inchesto a few feet in length, and are mostly un-propped. These transversemicro-fractures 4 tend to provide a high effective leak-off of thefracture fluid during fracturing, e.g. as high as 50% of the fracturefluid injected in one aspect, up to 40% of the fracture fluid injectedin another aspect, and up to 30% of the fracture fluid injected inanother aspect. A far-field area 5 can have substantially un-proppedfractures, and generally provides little or no production.

A partitioning of the fracture fluid is possible—that is, calculatingand/or estimating where the fracture fluid goes. It is estimated that5-8% may imbibe into the tight shale rock during pumping of a stage(over about an hour and a half pumping); 18-20% may be surrounding theproppant in the propped fracture region 3; 50% or more may be estimatedto be in the transverse micro-fractures 4; thus leaving about 20-25%that will be in the far-field un-propped fractures 5. These areestimates, and will vary depending on the tight shale, the fracturefluid, the in-situ stresses, and the overall fracture design.

Sealing of the Transverse Micro-Fractures

A large part of the fracture fluid, up to 50% or more, is in thetransverse micro-fractures 4. Resisting this fluid loss, by resistingthe formation of transverse micro-fractures and/or sealing existingand/or newly formed transverse micro-fractures, can have a drasticimpact on the fracture propagation by: reducing the fracture fluidrequired; changing the fracture from more complex to simpler; having alarge effect on the proppant transport; providing different proppedfractures; and/or allowing fracture control to improve reservoircontact.

Virtual Model of Fluid Driven Fracture Propagation in Complex ShalesUnder High Compressive Stresses

Certainly fluid driven fractures in non-homogeneous, non-continuum,complicated shales under high compressive stresses is a complex process.It is a process that has attracted many researchers to make calculationsof ideal materials in an attempt to simulate the process. And it is aprocess that has caused many practitioners to throw up their hands infrustration and proceed with a full understanding that they do notunderstand the process in detail.

The belief is that if one has the correct mental picture of the process,then modeling this process as is possible can lead to optimization. Themany “ideal” calculations and the few calculations consideringcomplicated effects such as non-elastic rock behavior, coupled fluidflow and fracture, and the like are indeed most helpful and clearlyguide the development of the virtual model. Likewise, the vase number ofhydraulic fracturing well stimulations underway in the complicated tightshales—as well as the million or so hydraulic fractures performed inmany formations over the past nearly seventy years—are the basis for anyproof tests of any thought processes or models. In between, are a numberof laboratory tests on small scale and large scale samples of simulationmaterials and shales that provide correlations and calibrations offeatures of different processes and some models.

Even with this vast background of simplified calculations, laboratorytests, and field experience, it is correct to say that hydraulicfracturing of the shales for oil and gas production stimulation is notwell understood. After all, it is not possible to actually “see” theprocess. Nevertheless, the industry has been incredibly successfulrelying on a process of drilling, fracturing, and production tocalibrate out to a large extent the details of the rock properties andthe in situ stresses.

What is presented here are the ingredients to form virtual model that isa better mental picture. The research focuses on the role of thefracturing fluid, and how to optimize the fracturing fluid and thepumping.

Importance of the Rock

Many agree that the missing link to understanding hydraulic fracturingis the lack of understanding of the reservoir rock. Organic-richmudstones (the so called “tight shales” or “black shales”) areheterogeneous at all scales, and on the micro scale are non-continuous.

These rocks are composed of hard strong sub-micron size mineralparticles, clay platelets, organic matter, and micro to nano meter scalepores filled with different fluids including water, methane, andhydrocarbon liquids. The mudstones may range from calcareous toargillaceous with detrital quartz and other particles, high clay contentranging to 20% or more. Pyrite is common with bitumen vitrinitesometimes present. Volcanic layering may be present as well as calciteveins. Total organic content may range from a few percent to 10% byeight (about double by volume). Total porosities range from a fewpercent to 6-8%. The organic content may be widely dispersed or inabundant clumps, and may be surrounding mineral particles or filing gapsaround mineral particles.

It is impossible to imagine that a substance composed of hard strongmineral grains, clay platelets, organic matter, pores filled with fluidsranging from gases to liquids would behave as a homogeneous continuumelastic material. They do not. When one considers failure it can beimportant to realize that at some scale the substance “comes apart”—itbreaks. In the “coming apart process”, because of the high far-fieldcompressive stresses environment, shearing may be more easily visualizedrather than tensile failure. We may visualize absolute tensile failureoccurring just at the fracture tip as the fracture fluid “pries” openthe rock to “come apart”, but the process may be more shearing andextension type failure. One can also visualize shearing and possiblecompaction, and micro pore fluid and pore pressure adjustments occurringjust past the actual crack tip before the rock finally “comes apart”.And, it is very plausible to visualize a time dependence for the “comingapart”, a failure process that may be due to thermally activatedprocesses such as stress corrosion or chemo-mechanical processes, or dueto fluid movements and pore pressure adjustments. The latter shouldcertainly be happening and will require some time to occur.

The shales also contain discontinuities—often called “planes ofweakness”—consisting of layer or bedding interfaces, natural and usuallytightly filled fractures, thin interfaces or zones of differentmaterials, and high-strength inclusions. The layering may be associatedwith the depositional environment, but the properties change over timedue to non-homogeneous digenesis transformations. This leads to bothvertical and horizontal variations. Interface makeup and mechanicalproperties variations between the shale units can result in these weakinterfaces (shear strength wise). Often layering or bedding interfacesmay be approximately horizontal and align approximately with theprincipal directions of the in situ stresses. Other times the rockprincipal material properties directions may not align at all with theprincipal stress directions.

Bulk unconfined strength may vary from 10,000 psi to 35,000 psi; andvariations in Young's Modulus range from 1 million psi to 5 million psi.These bulk properties can change over small intervals that vary frominches to feet. An apparent fracture toughness—a quantity ill-definedfor the shales with no precise method of measuring under highcompressive stresses—tends to give fracture pressures in the range of18,000 psi to 24,000 psi. This is based on thick walled cylinderconfined pressure measurements (the standard to infer fracture toughnessof rocks). This is a surprisingly small range for a variety of shales,even though the shales show large variations in their makeup and theirstrength and stiffness. This is possibly due to the in-precise techniquefor the inferred fracture toughness; nevertheless, this is thestate-of-the-art.

Based on the known shale make-up, it is not reasonable to believe thatshale fracture occurs as for a homogeneous continuum elastic-brittlematerial. This has to be taken into account in considering the numerouscalculations that do treat the shale as a homogeneous continuum, whethertaken as elastic brittle or some non-linear representation.

Hydraulic Fracturing—The Process

A well can have a vertical section that is turned to create a horizontallateral portion of the well. The vertical section may be of the order ofone to two miles deep, and the horizontal lateral may be from over ahalf mile to about two miles in horizontal length. Fluid is pumped athigh pressure into the lateral section to create fractures.

In practice the hydraulic fracture complicated. How the fractureemanates from the wellbore is not clear, but generally it is assumedthat a single fracture propagates from each perforation cluster, notchedinterval, or sliding sleeve opening, and growth tends to be at leastsomewhat centered around the wellbore. The fracture may be somewhatelliptical in shape not necessarily symmetrical about the well bore. Forthe shales these will be branching and step-over's leading to a complexfracture network. Furthermore, it is not uncommon for the fracture toreach a layer interface and turn and propagate horizontally within thelayer interface for some distance, or even for long distances. Fracturewidth in the ‘main’ fracture area may be about 0.2 inches (maybe twiceto three times that width just at the wellbore) and decreasing somewhatwith fracture length depending on the shale stiffness and otherproperties, in situ stresses, the pumping rate, and the fracture fluid.

During hydraulic fracturing the fluid pressure is increased until rockfailure occurs, with the highest pressure referred to as “breakdown”,when a micro fracture occurs. Pumping of clear fluid (the pad, noproppant yet added) typically is first done and the new fracture iscreated.

At some time proppant (most often sand but sometimes ceramics or othermaterials) is added to be carried with the fracture fluid and ultimatelyleft in the fracture to prop open the fracture after pumping stops.Pumping a stage may require an hour and a half; some fracture fluid willbe “squeezed” from the fracture and returned to the surface as“flowback” after pumping stops—but typically not immediately, maybe daysor weeks after. In detail, the process is complicated and involves muchart and practice that has been developed over time by industry drillingtens of thousands of shale wells.

In considering hydraulic fracturing it is helpful to consider the“parts” of the hydraulic fracture as shown in FIG. 1 (in which “half” ofthe fracture is shown schematically): 1) there is the breakdowninvolving the wellbore conditions, the fracture fluid, the rock, in situstresses, and other factors; 2) there is the near wellbore fracture,sometimes called the “connector” 2, extending out the first few feet tomaybe ten feet from the wellbore (this part is clearly affected bystress shadowing from other fractures); 3) there is the propped fracture3 extending fifty to maybe one or two hundred feet in distance from theconnector, which accounts for nearly all of the well production; 4)there is the transverse micro-fractures 4 abutting and at high angle tothe principal fracture (likely these fractures are a few inches to a fewfeet in length and are mostly un-propped, but tend to provide a higheffective leak-off of the fracture fluid during fracturing, maybe ashigh as 50% of the fracture fluid injected); and 5) there is thefar-field primarily un-propped fractures 5, that generally provide no orlittle production.

In considering hydraulic fracturing it is helpful to partition thefracture fluid—that is, where does the fracture fluid go. It isestimated that 5-8% may imbibe into the rock during pumping of a stage(over about an hour and a half); 18-20% may be surrounding the proppantin the propped fracture region 3; 50% may be estimated to be in thetransverse micro-fractures 4; this leaving about 25% in the far-fieldun-propped fractures 5. These of coarse are estimates, and will varydepending on the shale, the fracture fluid, the in situ stresses, andthe overall fracture design.

This invention focuses on the fracture propagation of the proppedfracture area 3 and 4. Emphasis is on how the fluid driven fracturepropagates once breakdown and fracture initiation has occurred at thewellbore. It is this fracture network that will ultimately provide thefluid conducive paths for the drainage of the fluids from the reservoirto the wellbore for production. The work further focuses on how thefracture fluid and pumping affects this fracture propagation, with theintent of favorably manipulating the fracture propagation.

Although the invention here focuses on the fracturing fluid and pumping,it is worth noting that the fracture fluid must do three things—createthe fracture, carry the proppant, and leave a connected, conductivepropped fracture. The invention here focuses on the first with the aimof optimizing fracture fluids for hydraulic fracture creation. Indeed,if the proper fracture network in contact with the reservoir is notcreated, there is no hope of achieving high productivity no matter howwell the other two functions are achieved. It is noted that the role ofthe fracturing fluid on the creation of the fracture has generally notbeen considered discretely beyond the fluid's viscosity and the pumpingrate.

Hydraulic Fracture Propagation “Main Drivers”

First Principles: Hydraulic fracture propagation in complex shaleformations under high compressive stresses is complicated. It is anun-calculateable problem in detail; basic parameters are unknown; and noone can actually see in detail where the fracture goes in order tovalidate any analysis. Thus, in order to optimize this most importantprocess for the recovery of oil and gas (and although not discussedhere, as a foundation for improved enhanced geothermal energy recovery),it is appropriate to break hydraulic fracturing into “main drivers”, andto understand each such driver considering “first principles”. Previousnumerous calculations and modeling that include approximations andassumptions can then be used to better correlate with field observationsand to guide optimization. Following this concept, hydraulic fracturingis considered here requiring a consistency with each “main driver” ofthe process following “first principles”. The fracture propagation “maindrivers” to be considered are as noted below:

1. The rock is not homogeneous and continuous. It is made up of hardstrong submicron size mineral particles, clay platelets, organic matter,micro to nano meter scale porosity, and different fluids in the pores,invariably including water, gas (mostly methane), and hydrocarbonliquids.

2. The rock has many discontinuities such as lithology changeinterfaces, natural filled fractures, and inclusions. Many of thesediscontinuities are planes of weakness in terms of shear strength andtensile strength. This rock fabric exists at the macro scale of feet anddown to the micro scale of microns.

3. The fracture fluid and the proppant must “go somewhere”. They occupyspace, and conservation of mass analysis can be very helpful tounderstand fracture propagation.

4. The pumping (injection) rate, pumping pressure, and the fluidinjected are knowns. Nothing else is precisely known.

5. Microseismic measurements (and sometimes surface Tiltmetermeasurements), production data, reservoir drawdown pressure are commonlyavailable to help to estimate hydraulic fracture locations. Someborehole temperature and vibrations (sometimes measured in the lateralsduring hydraulic fracturing and/or production) and the use of tracerfluids or tracer proppants also can help to locate hydraulic fractures.Electromagnetic measurements and cross-well tomography are beingresearched as added methods to detect hydraulic fractures and proppantlocation. Adjacent bore holes may also assist to identify hydraulicfractures, as well as production logging to infer zonal productionlocations along the lateral.

6. In considering “first principles” it should be remembered that theshale is not well characterized to the level of the fracturepropagation, in situ stresses tend to at best be known only in generaldirection and global magnitude, and pore pressure tends to be inferredindirectly over time as a play is developed.

Fluid Driven Fracture Propagation: Fracture propagation—crack growth—isa macro process considering the huge injection of high pressure fluids,of the order of 15 barrels per minute for a single fracture network(i.e. pumping at 70-80 barrels per minute per stage with 5 clusterswithin a stage that may each yield one fracture network). However, atthe crack tip the extension becomes a very micro process. The rock hasto part, starting at the sub-micron scale. It is this crack tip processthat controls the macro process of driving the network via injectinghuge volumes of fluid at high rates. FIG. 3 is an illustration showingthe macro process—the crack tip micro process. Ideally the crack extendsin the direction of the maximum horizontal stress, allowing the crack toopen in the direction of the minimum horizontal stress. This is ofcourse ideal, assuming that the vertical in situ stress is the greateststress, and that the in situ principal stress directions align with thecrack principal directions. And of course, the in situ stress principaldirections may or may not align with the rock material propertyprincipal directions. Fracturing is a competition between stresses andthe rock properties.

The process may be visualized as the following. For homogeneouscontinuous rock (considering an ideal situation), as more fracture fluidis injected into an already existing fracture, the fracture dual “pries”the fracture further open by the fracture fluid pressure increase.Stresses change in the rock all around the fracture and particularly inthe region of the fracture tip. These stress adjustments travel with thespeed of sound in the rock, several thousand feet per second—exceedinglyfast, almost instantaneously for the process here. For anelastic-brittle substance (maybe more like granite rock, but not theshales) shear and tensile stresses would build in the region very nearthe crack tip. When a certain stress intensity is reached in this verysmall region near the crack tip, fracture propagation—extension—occurs.(Conventional analysis most often would use an energy criteria allowingthe fracture to grow for a given energy input, with growth continuinguntil the energy required to create the new fracture surface area equalsthe energy input.)

The crack propagation speed isn't well known; some estimate about halfthe speed of sound in geo materials. The Rayleigh wave speed would be anupper bound, about two-thirds the speed of sound for ideal rock. Thefracture fluid will start to move with the crack growth, but cannot keepup with such high crack growth speed. At best the fluid velocity couldbegin to move at the speed of sound in the fracture fluid, as the fluideffectively decompressed in the fracture. Without the fluid keeping upwith the crack growth, the crack eventually stops growing. The fluidcatches up, wedging opening the fracture; the crack eventually growsagain; and so forth. A step process would seem to occur. (Laterdiscussion will occur regarding the expected step lengths and what mightchange the propagation from step wise to continuous growth.)

For the shales (which are not a homogeneous continues material), theabove fracture propagation model is not completely the case. As fluid isinjected into an already existing fracture and fracture fluid pressureincreases, and stress adjustments do occur with the speed of sound inthe shale. And, stresses near the crack tip increase, and lead to shaledamage in a region near the crack tip. The behavior will not be justelastic-brittle behavior. This creates a three dimensional “processzone” around the crack tip (which may be somewhat analogous to a“cohesive zone” sometimes referred to in the literature). The processzone size, shape, and the damage are not well known; this process zoneis discussed below.

Crack Tip Details: What happens at the crack tip can be important. FIGS.4 and 5 suggests two possibilities for the crack tip configuration. One(FIG. 4) is a very blunted crack tip creating a larger fracture widthtoward the crack tip. The other (FIG. 5) suggests a very pointed cracktip and a narrow fracture width toward the crack tip. Unfortunately, thecrack tip configuration is not well known as it is not possible tovisualize the crack tip as the crack is growing under conditions of highcompressive stresses. Different shales may exhibit different crack tipshapes due to the shale make-up. Speculation here is toward the pointed,sharp crack tip for most shales.

For the sharp crack tip (and likely even for a blunted crack tip), it iscertain that there will be a dry zone near the crack tip. That is, therewill be a region where fracture fluid cannot ever reach. As the fracturepropagates, a near absolute vacuum momentarily occurs as the crackgrows, to first be filled by vaporization of shale fluids and fracturefluid.

The potential of a dry zone near the fracture tip is not new, and hasbeen considered in a few fracture calculations. It has beenmeasured/observed to some extent in laboratory tests. An exception maybe for a fracture fluid that would wet the rock and be mobilized bycapillary pressures, or for gaseous fracture fluids or fluids that canbe vaporized at low pressures such as CO2 that could rapidly expand fromsupercritical to gas. Shales that would produce a ‘wider’ fracture nearthe tip (the “blunt tip” illustrated in FIG. 5) would undoubtedly showat least somewhat different fracture propagation than a shale with amore pointed, sharp crack tip.

The implications of a dry zone can be important. Overall, it seemslikely that fracture fluid, and certainly not proppant, will never reachthe crack tip during the hydraulic fracturing process, other than forthe exceptions as noted above. “Tip screen-out” does not mean thatproppant actually reaches the crack tip. It means that proppant hascompacted and bridged in the fracture and will not move, possibly in thevicinity of the fracture tip, but not at the crack tip.

Crack Tip Process Zone: The shales are not homogeneous continuummaterials at the micro scale. Confocal microscope images of a shale showthe laminations even at the micro scale. The region of stress intensitynear the crack tip will be affected by this shale micro complexity.

Unfortunately, only limited observations of the crack tip process zoneare available, and any such images that are available are after thecrack has grown and the sample has been unloaded. (Some attempts havebeen made to capture the shale crack tip structure before the sample isunloaded by using injected epoxy or a liquid metal that will solidifybefore unloading.) The limited observations suggest that slip hasoccurred along the micro laminations. That is, the deformation in thecrack tip stress intensity process zone has occurred by shear slip. Suchslip along micro planes of weakness would lead to the shale constituentsrelocating that could either cause compaction or dilation in the processzone. With respect to any dilation, clearly micro cracks are notexpected to be created in this zone due to the high compressivefar-field stresses. A micro crack would cause the shale to compressoutward from the zone as the shale always “has to go somewhere”. Infact, it would seem more likely that the region near the crack tip maycompact. Whether compaction or dilation occurs, the pore fluids wouldrearrange and local pore pressure would change.

FIGS. 6 and 7 show suggested process zone stress intensity profiles thatmay occur. Assuming in this illustration that the layering at the microscale is approximately horizontal, then different process zone patternswould be expected depending on whether the crack is growing verticallyor horizontally. FIG. 7 shows the stress intensity profile that mayexist for a fracture growing vertically across the laminations. FIG. 6shows the stress intensity profile that may exist for a fracture growinghorizontally parallel to the laminations. The size of these stressintensity profiles where slip has occurred is speculated as opposed toreal observations, but is believed to be at least several centimeters.

A process zone at the crack tip is not new, and several calculationshave included process zones in the crack propagation analysis.(Sometimes this region has been referred to as a “cohesive zone”.) Whatis new, is the appreciation that the process zone is related to shearslip along the micro laminations, that the process zone is “anisotropic”(at least in some shales), and that different shales may have differentprocess zones related to the micro lamination structure. No informationis known regarding the re-adjustment of the pore fluids or pore pressurein this process zone region.

In any case, at some stage the damage in the process zone is sufficientto allow parting (separation) of the material. Stresses across theparting area must be at least zero, although the failure may be byextension rather than a pure tensile failure. The fracture propagates;that is, crack extension occurs.

Time Dependence of Process Zone Formation: The formation of the processzone for the shales, likely by shear slipping along the laminations (asnoted above), may be time dependent. The slip along the laminationswould require time to occur, and the formation of the process zone mayresult in the movement of pore fluids which would certainly be timedependent. Chemo-mechanical effects may also be part of theprocess—again time dependent.

Unfortunately no direct evidence is know regarding the time dependence,but some circumstantial evidence exists. For example, time dependencemay be speculated in that fractures propagation observations sometimessuggest that the fracture is growing much slower than the Rayleigh wavespeed (discuss below regarding velocity of the fracture fluid), and timedependence formation of the process zone would be an explanation.Another example suggesting a time dependence—on the scale of thefracture propagation—may be drawn from the numerous tri-axial stressplug tests. It is common to first load a plug sample to some hydrostaticstress to about the mean stress of the in situ shale (thousand of psi).Than at some later time (minutes to an hour) the test would progress byapplying a shear stress to failure. In observing these tests, nearly allshale samples show some short-term deformation between the hydrostaticand shear stresses. Time for decay of the deformation at constantboundary loads, tends to be relatively short, and may be due at least inpart to micro pore fluid equilibration.

Although the scale of the time dependence of the process zone formationis not known, it can be important. The crack can never “pass” theprocess zone; new process zone is formed as the crack grows. Thus if theprocess zone formation is time dependent, this would limit the crackgrowth velocity. In fact, if the process zone formation is sufficientlyslow, it may allow the fracture fluid to more nearly keep up with thecrack growth, and the crack would grow at the speed of the injectionrate. Certainly different shales would be expected to have differentprocess zone formation times, thus leading to different crack extensionvelocities.

Fracture Fluid Velocities During Fracture Propagation: Based on aconservation of mass, the fracture fluid velocity in the narrow fracturecan be estimated as the fracture length grows away from the wellbore.The fracture width and the leak-off into the surrounding formative canbe estimated. FIG. 8 shows fluid velocities in feet per second fordifferent leak-off conditions for a shale with intermediate stiffnessand estimated in situ stresses. The injection rate is 12 barrels perminute continuous at the wellbore of slick water as the fracture fluid.The estimated fracture widths are taken from a quasi-three dimensionalplanar fracture calculation with no height containment (approximatelycircular fracture). Three different leak-offs are shown, with the topline (0.001) no leak-off, the bottom line (0.003) leaking off about 50percent by time the fracture has grown 50 feet from the wellbore, andthe middle line (0.002) is an intermediate leak-off of about 25 percent.The fracture is taken as symmetrical around the wellbore; the “halflength” is the distance of the fracture tip from the wellbore.

Fracture fluid velocities beginning a few feet away from the wellbore(not right at the wellbore) range from about 10 feet per seconddeclining to about 1 foot per second at about 50 feet from the wellborefor a leak-off of nearly fifty percent by time the fracture has reached50 feet from the well bore (the bottom line). If non-homogeneousfingering would occur (instead of homogeneous circular growth), it isestimated that the fluid velocity in the “finger” fracture extensionwould have to be upwards of one hundred times the fluid velocity for thehomogeneous expanding circular fracture. The primary slowing of thefracture fluid velocities for a given injection rate and a given fluidis due to dispersion (increasing diameter of the fracture) and secondlyto fluid leak-off. Fracture width variation is a small effect.

Understanding the range of fracture fluid velocities can be important.High fracture fluid velocities would lead to large pressure dropsrequired to move different fluids through the narrow fractures. Thesepressure drops along the fracture for the high fluid velocitiescontribute to the complex fracture formation.

Fracture Fluid Properties: Although viscosity is well appreciated as acritical fracture fluid property affecting fracture propagation,compressibility and sound velocity (or density) of the fracture fluidare also critical properties. The density, viscosity, andcompressibility for several potential fracture fluids—water, CO2 andcertain foams are noted in Table 1.

TABLE 1 Critical Fracture Fluid Properties Viscosity DensityCompressibility Speed Sound Fluid (cP) (lb/gal) (×10⁻⁶ psi⁻¹) (ft/s) H₂O.4421 8.34 2.6 5383.53 CO₂ .0941 7.597 16.2 2241.54 N₂ .0322 3.017 55.11930.38 60% Foam Table 2-B 7.5 5.23 3975.23 70% Foam Table 2-B 7.79 6.313551.08 75% Foam Table 2-B 7.76 7.02 3373.21 80% Foam Table 2-B 7.717.92 3186.06 Viscosity (cP) Shear Rate (sec⁻¹) Fluid 200 800 1200 140060% Foam 117 37 26 18 70% Foam 120 46 34 26 75% Foam 126 48 36 27 80%Foam 127 49 36 30

Data on rheological properties of these selected fluids and a Matlab™software tool were used to estimate fluid characteristics based onpressure, temperature, and fluid composition. Foam rheology wasdetermined from a combination of pure fluid properties and an equationof state developed by Lord. Table 1 shows properties at a constanttemperature of 150° C. and 7000 psi pressure. It is interesting to notethat the difference in compressibility and speed of sound between fluidsthat may be thought of as gas versus a liquid do not vary so drasticallyunder high pressure (at this temperature).

Supercritical CO2 and foams have attracted the attention of hydraulicfracturing operators (as alternatives to slick water) due to theirunique and different properties. However, in considering the fluidproperties it can be important to keep in mind that once past thecritical pressure/temperature, the distinction between a gas and liquiddoesn't exist. For example, from the phase diagram of CO2, it becomesclear that at high compression as would be the case for a fracture fluidand at modest reservoir rock temperatures, the CO2 properties do notchange significantly except as discussed later, near the fracture tipwhere pressures may be low to even vacuum. Thus for CO2 a phase changemay occur as the fracture is propagating as the pressure decreases inthe fracture, particularly near the crack tip. For slick water no suchphase change will occur except very near the crack tip wherevaporization may occur. Such large changes in the fracture fluidproperties between CO2 that may undergo a phase change and slick watercould have a large impact on fracture propagation. Similar analogies canbe drawn regarding foams versus slick water.

For comparisons to develop a better mental picture, Table 2 showscritical properties at reduced pressure of 500 psi and 150 Ftemperature. It is interesting to note that at 7000 psi compression and150 F, CO2 has about 6 times the compressibility of water (Table 1). Butat 500 psi, CO2 has about 550 times the compressibility of water (Table2)—a very large difference. At 7000 psi compression and 150 F, water hasonly about 5 times the viscosity (in Centipoises) of CO2 (Table 1), andat 500 psi water has about 25 times the viscosity of CO2 (Table 2)—amuch larger change in compressibilities.

TABLE 2 Critical Fracture Fluid Properties at Reduced Pressure ViscosityDensity Compressibility Speed Sound Fluid (cP) (lb/gal) (×10⁻⁶ psi⁻¹)(ft/s) H₂O .4357 6.966 3.40 5117.8 CO₂ .01738 .4336 1861 876.33

Fracture Fluid Pressure Drop along the Fracture: Calculations showfracture fluid pressure drop as the fluid is flowing in a narrow channelat high velocities. FIG. 9 shows the pressure drop versus the fluidvelocity. This calculation is for water flowing in a 1 mm height channelwith wall roughness estimated as sinusoidal irregularities with heightof ten percent of the channel thickness.

For this case, pressure drop at 1 foot per second fluid velocity isabout 15 psi per foot, while at 10 feet per second velocity pressuredrop is about 340 psi per foot. And, at 100 feet per second velocity thepressure drop is about 1300 psi per foot. These pressure drops per footwould lower the net pressure in the fracture (the difference between thefracture fluid pressure and the rock pore pressure) significantly alongthe fracture length, particularly near the fracture tip even for clickwater. Considering that a net pressures as low as 50 psi has beenclaimed to cause a fracture to extend in the shales, the pressure dropsper foot shown above are large.

The fracture surface roughness can be an important factor. Differentshales show different fracture surface roughness—some relatively smoothand some much rougher. Also the fluid properties of viscosity and shalewetting or non-wetting can be key parameters and have yet to beconsidered in the calculations. The basis for these calculations notethat the flow resistance will increase as the cube at the channel heightdecreases. Thus as the fracture width decreases huge pressure dropsoccur. The Reynolds number is critical and an increase in the pressuregradient versus velocity tends to occur at about 10 feet per second (forwater) where the Reynolds number is a few thousand. It is clear thatpressure drop along the fracture should be considered.

Planes of Weakness

The formation shale rock contains many discontinuities, some are weak inshear and tensile strength and are referred to as planes of weakness.Discontinuities can be visible in shale. As a fracture approaches andintersects a discontinuity, whether or not a plane of weakness, thefracture may continue across the discontinuity, it may stop and progressat some other location, it may progress along the discontinuity a shortdistance and then progress in its original direction (a “step-over”), itmay branch and progress as two or more fractures in the same generaldirection, or it may progress along the discontinuity. How the fractureprogresses can be important for creating the fracture network; somefractures will be desirable while other fracture patterns undesirable.

FIGS. 6 and 7 also show schematics of the fracture near the crack tipapproaching a discontinuity. One should note that as a fracturepropagates, that the process zone first interacts with the plane ofweakness, before the “fracture” has arrived. One can logically assumethat the process zone size and shape will affect how the fracture willultimately interact with the interface. One can also logically assumethat a fracture growing in steps might interact with an interfacedifferently than a steadily growing fracture.

The interface shearing that must occur as the fracture approaches theinterface may have “its process zone” just as the intersecting fracturehas its process zone. One would ask whether the fracture propagationalong the interface (if such occurred) is by steps or steadilypropagating (the same phenomena as noted above for the main fracture).To a large extent only speculations can be made; however, this is atpresent the state-of-the-art.

The calculations although only approximations are helpful as guidance,but none of these calculations would appear to be correct from a physicspoint for shales. If a correct process zone is not considered, then thedetails of the dynamic process of the crack and fluid approaching andintersecting the interface would not be correct. Additionally the insitu stress state in the vicinity and across the discontinuity will becritical, and unfortunately is not known, nor is the in situ strengthand stiffness of the interface. If there is a stress jump across theinterface, that stress jump would tend to release locked in in situstresses as shearing or parting occurred with fracture fluid entering,and so forth.

Laboratory Validation Tests

Laboratory tests were conducted to validate certain phenomena notedabove. Tests tended to focus on breakdown, early crack initiation. Thetransparent materials (Plexiglas and glass) allow physical observationof the fracture pattern, while real rock better depicts the fluid drivenfracturing in shale formations. CT x-ray observations have been made ofboth the transparent materials and of the shale tests. Numerous idealfracture calculations have been made for these breakdown, early crackextension tests, almost always showing “good agreement”. Unfortunately,one of the most critical parameters for such calculations is fracturetoughness under high confining stresses, a parameter that is not easilydetermined for shale. Nevertheless, these past tests and fracturecalculations are valuable and do show certain phenomena.

Tests here are aimed specifically at validating the role of pre-existingdiscontinuities on fluid flow into the discontinuity. Clear acrylic anda 3-D printed ceramic material were used. Hydraulic fracture tests wereconducted using a tri-axial test system. Four inch diameter cylindricalsamples with a one-eight inch diameter hole (simulating the borehole)were subjected to confining pressure around the sample, and an addedaxial load was applied to create a deviatoric stress on the sample.Fluid was then injected into the borehole until the sample fractured. Aclear acrylic test sample was disposed between two steel end caps. Forthis test, the fracture initially grew outwards from the borehole inapproximately equal “wings”. One fracture wing stopped at the pre-cutslot in the sample (simulating a discontinuity, a plane of weakness)while the other fracture wing continued across the slot to the edge ofthe sample.

Clear acrylic and 3-D printed ceramic material samples have been tested.The 3-D printing allows “printing” continuities into the test sample,giving a high degree of flexibility for planes of weakness. Thistechnique is new, but sample test material that can practically beprinted is limited. This technique proved to be quite interesting.

The phenomena being validated was the leak-off of fracture fluid intoshale discontinuities, as noted as transverse micro-fractures in FIG. 2.The 3-D printed sample tests—and to a lesser extent the clear acrylicsample tests—showed that fracture fluid penetration can occur intolaminations (for the fluid used in the tests). This phenomena oftransverse micro-fracture leak-off can be important to fluid drivenfracture propagation in the shales. It is not well understood, nor wellappreciated, by industry at present, and is discussed more below.Previous calculations, however, have suggested when fracture may resultnormal to the main fracture for ideal material.

Discussion—Problems Remaining

Clearly the first principle “main drivers”, the observations noted, andthe speculations presented provide insight into how a fluid drivenfracture propagates in shale rock deep in the earth. This explainsbetter how a complex fracture network is created, and suggests howfracture propagation may be manipulated in some desirable manner. As thefracture intercepts a discontinuity in the rock, a number ofpossibilities are possible as previously noted. Each possibility willcreate a different hydraulic fracture network, and each possibilityoffers the opportunity for hydraulic fracture improvements. Consideringthe above, several observations can be made.

a) The fluid driven fracture may propagate in steps or continuously,depending on the fracture fluid properties and the process zoneformation. That said, it appears that the fracture fluid compressibilityand density, as well as its viscosity, and the shale micro fabric can beimportant properties affecting the formation of the process zone at thecrack tip and overall how the fracture will propagate. And, undoubtedlya fracture progressing by steps will intersect a discontinuitydifferently than a fracture that is progressing continuously.

b) Fractures will likely have a dry zone near the crack tip for shales.Fracture fluid will never reach thus region, and certainly not proppant.A “tip screen out” does not mean that proppant has reached the cracktip.

c) The process zone at the crack tip will be a damaged area due to shearslip along micro planes of weakness. The rock may compact in this regiondue to the far-field high compressive stresses, causing a redistributionof the pore fluids in the process zone. This process will undoubtedly betime dependent, and will vary with the shale. It seems clear that afracture progressing parallel to the micro planes of weakness will havea very different process zone from a fracture progressing across themicro planes of weakness. Therefore, a shale with a strong orientationof micro planes of weakness will fracture differently than a shalewithout. The significance of this will vary depending on the shale, andwill lead to different fracture propagation for parallel versus acrossthe shale micro fabric.

d) For a shale where the process zone formation is more time dependentand/or for a fracture fluid that is more compressible, a continuousfracture propagation is more likely to occur—what some might call aductile fracture requiring greater energy to create the fracture. Whilea shale where the process zone is not so time dependent and/or a lesscompressible fracture fluid might lead to fracture propagation insteps—and some might refer to this as a brittle fracture requiring lessenergy to create the fracture. For each case the complexity of thefracture would undoubtedly be different.

e) Based on fracture fluid velocities considering conservation of fluidmass and simple flow calculations, the pressure drop along the fracturecan be significant particularly nearer the crack tip. Fracture fluidpressure drop within the fracture will contribute to the complexity ofthe hydraulic fracture network when considering conventional pumpingrates. That is, the pressure drop in the fracture will be sufficient tocause the fracture fluid away from the pressure drop area, to create anew fracture emanating at a rock ‘weak link’, and the fracture willprogress along this new path. The same will subsequently happen for thenew path, and so forth. It should be remembered, however, that it is theshale fabric that is required in order to have complex fractures,irrespective of the pumping rates or fracture fluid.

f) Optimizing parameters of fracture fluid and pumping rate based oncritical shale properties would allow manipulating fracture propagation.It seems clear that of the many field experiments trying new hydraulicfracturing concepts, and correlating with the production results (somesuccessful and some not), that indeed fracture propagation manipulationis occurring. However, it is occurring uncontrollably and withoutunderstanding why. Considering first principles “main drivers”, helps tobetter understand how these field fracturing concepts work and how tooptimize them.

g) It should be understood that shale properties—including itsfluids—and the in situ stresses are critical characteristics for fluiddriven fracture propagation, and they are “givens”. In general theseshould be accepted and are not variables, except that stress shadowingeffects and pressure drawdown or maintenance do to some extent changethe in situ stresses. The in situ stresses affects can be key. Thisinvention has focused on the shale properties and on how the fracturepropagation may be influenced be the variable of fracture fluid andpumping for given shale properties and given in situ stresses.

Conclusions—Implications for Fracture Propagation and “Designer FractionFluids”

This invention has focused on understanding fluid driven fractures incomplex shales under high compressive stresses, with the intent ofoptimizing fracture fluids to help create the desire fracture network.The following implications for hydraulic fracturing are noted here:

1. It is widely accepted that the fracture propagation is greatlyaffected by the shale fabric. Additionally, fracture complexity is alsodependent on the high pumping rates that are typically used (70-80barrels per minute per fracture stage for example). It should beemphasized, however, that without the rock heterogeneity (includingplanes of weakness within the shale formation) complex fracture networkswould not occur and the fracture would be directed exclusively by the insitu stresses.

2. It appears that for slick water the fluid flow in the fracture atpumping rates of about 15 barrels per minute per cluster is near acritical Reynolds number where the pressure drop in the fracture willcontribute to more complex fracture networks. If not all clusters aretaking fluid in a stage being pumped, then the injection rate into theclusters that are taking fluid—at a higher rate—may result in a fracturenetwork quite different from where all clusters are equally takingfluid, because of the pressure drop in the fracture affect.

3. The fracture fluid's compressibility, and to a lesser extent density,can be important as well as fluid viscosity. Higher viscosities tend tocreate more complexity, while higher compressibilities may create lesscomplexity. Fluids that can undergo fluid property changes—possibly evena phase change—due to pressure drop along the fracture will lend togreater fracture propagation manipulation.

4. Early laboratory tests conducted here tend to confirm how thecreation of the transverse micro-fractures (see FIG. 2) occur. Suchfractures create a large effective leak-off. “Plugging” the transversemicro-fractures using either a very fine proppant or othermaterial—similar to a lost-circulation additive concept—could have asignificant effect on the fracture propagation. Considering that may beas much as 50 percent slick water fracture fluid is lost to thetransverse micro-fractures, changing this large effective leak-off willreduce water required.

5. For shales that exhibit high micro laminations, it will be moredifficult for fracture propagation across these laminations versuspropagation parallel to the laminations. If the laminations areapproximately horizontal, this will lead to more elliptical heightcontained fractures; and conversely for laminations not horizontal.Furthermore, the micro laminations contribute to the size and shape ofthe process zone at the fracture tip (see FIGS. 6 and 7) affecting howfractures will interact with planes of weakness.

6. For shales that show a greater degree of micro creep, assuming thiscarries forward to a time dependence of the formation of the processzone, fracture propagation is more likely to be continuous as opposed tostep progression, and will be less likely to cut across planes ofweakness. For such a continuous progression the fracture will be moreprone to step-over's and complex fracture networks. The converse istrue. Continuous fracture propagation may be viewed as more ductilefracture, while step wise propagation may be viewed as more brittlepropagation—this may be the real definition of ductile versus brittlefracturing.

7. Shales that create a more rough fracture face surface when fracturedwill show greater fluid flow pressure drop along the fracture. Surfaceroughness plays a strong role as the fracture width becomes small andfluid velocities are high. The net conclusion of the rough fracture facesurface would be toward more complex fracture networks.

8. Fracture fluids play a large role in the formation of the hydraulicfracture network. It seems quite possible to optimize the fracture fluidproperties to manipulate the fracture network to some extent as desiredif the shale characteristics are known.

While the forgoing examples are illustrative of the specific embodimentsin one or more particular applications, it will be apparent to those ofordinary skill in the art that numerous modifications in form, usage anddetails of implementation can be made without departing from theprinciples and concepts articulated herein.

What is claimed is:
 1. A method for completing a wellbore, the methodcomprising: a) determining a fracture surface roughness for a givenformation rock, and for a give fracture fluid or pumping schedule orboth, prior to hydraulic fracturing; b) selecting a fracture fluid, or apumping schedule, or both, based on the fracture surface roughness andformation characteristics; and c) pumping the fracture fluid into thewellbore to create a desired fracture network.
 2. The method inaccordance with claim 1, wherein determining a fracture surfaceroughness comprises obtaining a core sample of the given formation rock,and conducting a fluid fracturing test, or a mechanical wedging fracturetest, or both, on the core sample.
 3. The method in accordance withclaim 1, wherein the selected fracture fluid, or the selected pumpingschedule, or both, based on the fracture surface roughness results in alower or a higher pressure drop along the fracture, as desired, tocreate a more productive fracture network.
 4. The method in accordancewith claim 1, wherein the selected fracture fluid, or the selectedpumping schedule, or both, based on the fracture surface roughnessfavorably alters interaction of a fracture propagation with adiscontinuity.
 5. The method in accordance with claim 1, wherein theselected fracture fluid, or the selected pumping schedule, or both,based on the fracture surface roughness changes a complexity or asimplicity of the fracture network.
 6. The method in accordance withclaim 1, wherein the selected fracture fluid, or the selected pumpingschedule, or both, based on the fracture surface roughness changesproppant transport through the fracture.
 7. The method in accordancewith claim 1, wherein the selected fracture fluid, or the selectedpumping schedule, or both, based on the fracture surface roughnesscauses or minimizes proppant screen-out.
 8. The method in accordancewith claim 1, wherein the selected fracture fluid, or the selectedpumping schedule, or both, based on the fracture surface roughnessincreases fracture length.
 9. The method in accordance with claim 1,further comprising: a) determining a fluid-rock interaction, includingwetting or non-wetting between a fracture surface and the fracturefluid; and b) selecting the fracture fluid based on the fluid-rockinteraction.
 10. The method in accordance with claim 9, whereindetermining the fluid-rock interaction comprises obtaining a core sampleof the given formation rock, and conducting a fluid wettability test onthe core sample.
 11. The method in accordance with claim 9, wherein theselected fracture fluid based on the fluid-rock interaction: a) resultsin a lower or a higher pressure drop along the fracture, as desired, tocreate a more productive fracture network; b) favorably altersinteraction of a fracture propagation with a discontinuity; c) changes acomplexity or a simplicity of the fracture network; d) changes proppanttransport through the fracture; e) causes or minimizes proppantscreen-out; and/or f) increases fracture length.
 12. A method forcompleting a wellbore, the method comprising: a) obtaining a core samplefor a given formation rock with formation characteristics; b) conductinga fluid fracturing test, or a mechanical wedge test, or both, on thecore sample; c) determining a fracture surface roughness for the givenformation rock based on the core sample; d) selecting a fracture fluid,or a pumping schedule, or both, based on the fracture surface roughnessand the formation characteristics; and e) pumping the fracture fluidinto the wellbore to create a desired fracture network.
 13. The methodin accordance with claim 12, wherein selecting the fracture fluid, orthe pumping schedule, or both, further comprises selecting the fracturefluid, or the pumping schedule, or both, based on the given formationrock, and given stresses in the formation, to create the desired facturenetwork.
 14. The method in accordance with claim 12, wherein theselected fracture fluid and/or the selected pumping schedule based onthe fracture surface roughness: a) results in a lower or a higherpressure drop along the fracture, as desired, to create a moreproductive fracture network; b) favorably alters interaction of the-afracture propagation with a discontinuity; c) changes a complexity or asimplicity of the fracture network; d) changes proppant transportthrough the fracture; e) causes or minimizes proppant screen-out; and/orf) increases fracture length.
 15. The method in accordance with claim12, further comprising: a) determining a fluid-rock interaction,including wetting or non-wetting between a fracture surface and thefracture fluid; and b) selecting the fracture fluid based on thefluid-rock interaction.
 16. The method in accordance with claim 15,wherein the selected fracture fluid based on the fluid-rock interaction:a) results in a lower or a higher pressure drop along the fracture, asdesired, to create a more productive fracture network; b) favorablyalters interaction of the fracture propagation with a discontinuity; c)changes the complexity or simplicity of the fracture network; d) changesproppant transport through the fracture; e) causes or minimizes proppantscreen-out; and/or f) increases fracture length.
 17. A method forcompleting a wellbore, the method comprising: a) determining a desiredfracture surface roughness for a given formation rock prior to hydraulicfracturing; b) selecting a fracture fluid, or a pumping schedule, orboth, based on the desired fracture surface roughness for the givenformation rock and anticipated stresses in the formation; and c) pumpingthe fracture fluid into the wellbore to create a desired fracturenetwork.
 18. The method in accordance with claim 17, wherein determininga desired fracture surface roughness comprises obtaining a core sampleof the given formation rock, and conducting a fluid fracturing test, ora mechanical wedging fracture test, or both, on the core sample.